The current invention relates to a method for enhancing formation stability during well construction. The method of the current invention improves the process of formulating cementing fluids (flushes, spacers, and cement slurries) such that the fluids reduce the risk of formation instability during well completion operations. More specifically, the current invention relates to a test for determining the optimum cementing fluid formulation for use in water sensitive, reactive formations.
Water sensitive, reactive formations include but are not limited to marl, clay bearing sandstone, clay bearing carbonates, shale stringers in salt formations and carbonate formations. Shales are among the most commonly encountered formations. Shales are fine-grained sedimentary rocks composed of clay, silt and in some cases fine sands. For the purpose of this discussion, shale will be termed as a loosely defined heterogeneous argillaceous material ranging from clay-rich gumbo (relatively weak) to shaly siltstone (highly cemented), with the common characteristic of having an extremely low permeability and contains clay minerals. Argillaceous formations like shales make up over 75 percent of drilled formations and cause over 90 percent of wellbore instability problems. Instability in shales is a continuing problem that results in substantial annual expenditure by the petroleum industry—in excess of a billion dollars according to conservative estimates.
A drilling fluid system (drilling mud) is an essential part of a conventional drilling process and consists of different solid and fluid components. When interacting with subterranean formation material such as shale and other water-sensitive, reactive formations, cementing fluids exhibit many of the same physical and chemical functionalities and properties as drilling mud. Different performance enhancing components may be added to any of these fluids. As known to those skilled in the art, the primary functions of a drilling fluid include the removal of rock material during drilling, imparting hydraulic support to the borehole to help ensure stability, providing lubrication to reduce friction between the borehole surface and drill pipe, cooling the drill bit, etc. Cementing preflushes and spacers serve the function of removing the drilling fluid in preparation for the cement slurry, as well as separating potentially incompatible drilling fluids from cement slurries. Finally, the cement will serve the ultimate function of zonal isolation and structural support. In each instance, the properties of these fluids are adjusted to account for the changing characteristics of wellbore formations encountered.
Cementing fluids often include several different salts (e.g. NaCl, KCl, and CaCl2) for various purposes such as intentionally affecting (shortening) slurry set times, cementing across salt formations, and supposed protection of productive formations that may contain water-sensitive clays. Historically, salt content in cement slurries has varied from one or two percent to saturation with NaCl. Use of KCl and CaCl2 is usually limited to no more than three or four percent. Further, seawater or brine is frequently added at the wellbore location to the cement composition as makeup water to produce a cement slurry having a suitable density and pumpability.
However, the use of salts in cement slurries has not been consistent with respect to formation issues. The position is frequently taken that the high pH of cement slurry, along with its minimal amount of calcium in solution, will suffice to provide formation protection in most cases. However, very little actual supporting evidence for this assumption has been found. Further, most testing reported in the literature has been based on regained permeability testing of sandstone cores. Although very meaningful to the understanding of that specific issue, any connection between effects on clays in permeable sandstones and formation instability as related to shales is complicated by precipitation of various calcium salt species from cement slurries. The pros and cons of this issue are frequently debated with no clear outcome. When salts are applied, presumably for formation stability purposes, it is frequently done without a true understanding of the method or outcome. Additionally, use of salts specifically in cementing spacers and preflushes is seldom applied.
In addition to salts, there are many other additives in cementing fluids. Polymers of many types (e.g. blends containing HEC, CMHEC, and various synthetic polymers) as well as silicates are a frequent component in cement slurries. They serve several functions including prevention of slurry dehydration and annular bridging during placement, enhanced bonding across permeable zones, rheology adjustment, and as an aid to gas migration control. However, combining salts and fluid loss additives in the same slurry frequently presents a more complicated and costly scenario because many fluid loss additives do not hydrate and/or otherwise function as efficiently in the presence of high concentrations of soluble salts. This cost-driven approach to achieving cement slurry fluid loss values has resulted in the reduction and general elimination of salts in most primary cementing slurries without a true understanding of the resulting effects on wellbore stability.
Thus, a need exists for a method of accurately formulating cementing fluids which will enhance formation stability.